Selected abstracts from the upcoming SPE APOGCE are presented below. Register for the conference here: http://www.spe.org/events/en/2016/conference/16apog/registration.html
Early Field Life Interference Pulse Test Design to Refine Reservoir Uncertainties: A Reservoir Surveillance Opportunity for the Wheatstone Gas Field, Australia. SPE 182325
Matthew Flett, Mathieu Muller. Chevron Australia Pty Ltd
The initial well proving and early production period of a hydrocarbon field is a valuable and unique period of field surveillance where there is the opportunity to narrow the range of uncertainty for key reservoir properties through the use of inter-well interference testing. The Wheatstone gas field, currently being developed as part of the Wheatstone liquefied natural gas (LNG) project, is located offshore north-western Australia. The start-up of the Wheatstone field, due to the nature of constrained ramp-up for LNG supply and location of development wells provides a unique opportunity for early field life interference testing. This is due to periods of individual well and well combination flows that are ideal for pulse generation and detection, with many development wells observing potential pressure responses while nearby wells are flowing. This paper will focus on the potential of initial well proving flows for pulse testing at the Wheatstone field to capture reservoir information.
Pulse testing can potentially be an important reservoir diagnostic tool, particularly during early production when the field is at initial state. Through considered test design strategy, detection of a pressure pulse in an observed well can be used to infer inter-well reservoir connectivity, connected pore volume and transmissibility. This paper provides a method to refine reservoir pore volume ranges and transmissibility. This will be accomplished through the use of dynamic model derived pulse testing type curves using homogeneous reservoir properties to match observed signals for selected active and observation well pairs within the Wheatstone field.
A suite of dynamic models exist for the Wheatstone field. These models cover a wide range of possible realisations for reservoir outcomes that affect initial static volumes and dynamic responses including structure, reservoir net to gross ratio and petrophysics (porosity, permeability and saturation). Selected dynamic models that reflect the uncertainty in inter-well connectivity, driven by variations in net to gross ratio and petrophysics, were run to develop well proving profiles for selected development wells, with non-active wells observing for a pressure pulse from this activity. Following the reservoir simulation uncertainty study of well proving flows, a homogeneous reservoir property simulation model was developed based on the reference mid case dynamic model, with constant porosity and permeability applied to active reservoir cells in the mid model. A variety of type curve pulse responses were developed for a range of porosity and permeability ranges for well pairs. These homogeneous type curves are then used to match reservoir model responses for the well proving uncertainty study, leading to estimates of potential average pore volume and permeability between well pairs. Thus the use of homogeneous reservoir model matching of interference signals during initial field conditions can be employed to appraise inter-well reservoir property ranges.
Discovering New Hydrocarbon Pay Sand Beyond The Wellbore With Reservoir Mapping While Drilling Tool – A Case Study From Offshore Sabah, Malaysia. SPE 182184
Ko Ko Kyi, Nazri Abdul Latiff, Kok Kwi Yen, Danial Saadon, M Ikhlas Rahim, Juhaidi Jaafar, Tomi Afandi and Ng Kiang Fei – PETRONAS
Tango Field, located offshore Sabah in East Malaysia, is a mature field which has been producing oil and gas for more than forty years. This field has many fault blocks, thus creating barriers to fluid and pressure communication between different fault blocks. Furthermore, the reservoir sands are turbidite sands which are difficult to correlate across the whole field. Being fan lobes, it is not easy to target these sands in drilling development wells. As part of the campaign to improve recovery and sustain production, two infill wells were drilled during 2014, by sidetracking two existing wells from the Tango-B Platform, which is located in the western part of the field. The target reservoirs are M1 and M2 sands, which still carry some upside potential based on the latest review of the field performance. To properly target and penetrate these sands in the planned wells, the Reservoir Mapping While Drilling LWD (DDEM) tool, in combination with standard triple combo LWD (Logging While Drilling) tools, was deployed. This is to ensure that the well trajectory stays within the targeted sands and the bed boundaries are detected long before the drill bit exits the sand body. Unlike previous deep reading LWD resistivity tools, the DDEM tool is a Deep Directional Electromagnetic Propagation tool which has the capability to see about 30 meters laterally beyond the wellbore. While drilling the first well, the target sands were penetrated as planned. However, there was a pleasant surprise where a new hydrocarbon sand was detected by the DDEM tool about 10 meters below the wellbore. The DDEM reservoir mapping software was used to image the newly found sand body. Based on this new finding, the drilling Bottom Hole Assembly was pulled back and the hole was side-tracked to target this new sand, which was successfully penetrated and completed. This new sand, which would not have been discovered with standard LWD tools has increased the well production by a factor of two or more. Being a turbidite sand, it was not picked up on the surface seismic section. The reservoir mapping software technology, together with the deep sensing resistivity imaging LWD tool, was instrumental in finding the new hydrocarbon sand which has substantially increased the production of Tango Field.
Application of Subsea Demulsifier Chemicals to Reduce Heavy Oil Emulsion Viscosity and Enhance Production in the Pyrenees Development. SPE 182217
M.L. Gilbert, D.A. Morley, P.A. Elliott, BHP Billiton Petroleum
The Pyrenees development consists of six low GOR, highly biodegraded oil accumulations (19-21°API) located offshore Western Australia, producing since 2010 under the operatorship of BHP Billiton Petroleum. The fields are developed by 19 horizontal production wells with reservoir sections up to 3km long. The subsea wells are tied back to a Floating Storage Production and Offtake (FPSO) vessel via subsea manifolds, flowlines and risers. As field water cuts progressed above 10%, an increasing deviation between predicted and actual flowline pressure drop was observed, indicating the formation of tubing and flowline emulsions. The additional flowing pressure loss and consequent reduction in liquid production formed the basis for a debottlenecking project to treat subsea emulsions.
Flow assurance studies had identified Pyrenees crude as possessing a strong emulsion forming tendency and therefore contingency for subsea manifold demulsifier injection was included in the basis of design. After identification of suitable demulsifier chemical through laboratory testing, chemical treatment was initially undertaken via injection at the subsea manifolds. Initial demulsifier injection into the subsea manifolds reduced flowline and riser pressure drop by up to 25%, yielding a 4% increase in field oil production.
In an attempt to realise further pressure drop reduction, the prospect of downhole injection at each well was investigated. As downhole chemical injection had been initially designed for scale inhibitor, flow assurance studies were performed to ensure repurposing the lines would not result in elevated calcite scaling risk.
Downhole chemical injection was applied across the available wells and resulted in additional 18% field oil production uplift with individual wells achieving up to 50% increase in drawdown and 58% increase in liquid production. An added benefit of downhole demulsifier injection was stabilised flow regimes and pressures observed from the downhole gauge to the topsides riser.
The minimum stable flow threshold of demulsifier concentration was empirically determined to be in the range 60-140ppm liquid, below which, the Pyrenees wells entered a demulsifier induced slug flow regime.
Downhole demulsifier was generally found to have an effective treatment on Pyrenees wells between 30% to 80% watercut.
- Lower than 30% watercut, emulsions do not cause sufficient additional pressure drop to justify the cost of demulsifier chemical dosing.
- Pre emulsion inversion point (>30% watercut), demulsifier has an increasing effect with watercut, up to a maximum effectiveness between 65-80% watercut.
- Near emulsion inversion (75-80% watercut), demulsifier is required to keep the well in a stable flow regime as well transitions between contrasting fluid viscosities.
- Higher than inversion point (>80% watercut) well naturally flows in a stable, low viscosity flow regime. Demulsifier dosing does not have any significant impact above this watercut.
Analysis of demulsifier effectiveness post successful downhole implementation enabled the continuous optimisation of chemical usage against changing well watercuts, to maintain strong chemical cost efficiency.
This case study provides a practical example of opportunity identification and multifaceted problem solving to significantly and safely debottleneck production. The lessons learnt in this project may be carried across to other fields and facilities to assist identifying and resolving related flow assurance bottlenecks.
Code of Practice for the Construction and Abandonment of Petroleum Wells in Queensland – As Mandatory Safety Requirements. SPE 182246
Peter Lee; Queensland Department of Natural Resources and Mines (DNRM), Mika Porter and David Maggiori (Santos).
Queensland is regarded as one of the principal regions in Australia for mineral and energy production and future investment. It produces an array of products from a world-class energy industry, which has led to the development of world class value-adding industries such as LNG production. Approximately AU$70 billion of investment in LNG processing and production with gas from the Surat and Bowen basins has been realised in the state
In November 2014 a group of 17 industry professionals from two Australian States were tasked with developing the Petroleum well Code of Practice, facilitated by APPEA. The team hailed from DNRM in Queensland and the Department of State Development (DSD) in South Australia, supported by cross industry specialists from Santos, APPEA, Origin, QGC, Senex, Beach Energy and Armour Energy. The multi-discipline team brought previous industry experience operating under various different regulatory regimes to the project, ensuring good debate and challenge throughout the development of the Petroleum COP. Given the large area of the state of Queensland and the number of basins that a set of minimum well construction standards would need to apply to, the size of the task was significant. Recognising that the industry operates in a complex environment, the aim was to set a minimum standard for all petroleum wells. The wells covered by this code are petroleum wells constructed by petroleum tenure holders on their tenures for both conventional and unconventional oil and gas exploration and production. The goal was to develop a Code of Practice that addressed the petroleum well life cycle phases.
The principle of this new Code was to support an objective based regulatory regime rather than prescriptive requirements, and address the following main considerations, over and above the requirements set out in the existing CSG Code of Practice:
- Aquifer isolation,
- Possible use of oil based/synthetic muds for deeper wells,
- Hydraulic stimulation,
- Well integrity management, and
- Plug and abandonment.
The contents of the Petroleum COP fall into the following categories and ensure that adherence to the Petroleum COP protects an individual company’s licence to operate:
- a) Principles – the principles that underlie mandatory requirements.
- b) Mandatory requirements – requirements that are enforceable by the regulator and must be complied with.
- c) Good industry practices – recommended practices, methods and techniques to assist Petroleum tenure holders in satisfying mandatory requirements.
Ultimately, the benefits of collaborative development of a code will result in improved protection of groundwater resources in the state, acceptance by communities as an acceptable, transparent construction standard, and result in improved social licence for petroleum operations. In addition, a collaboratively developed code will result in consistency between CSG and other petroleum construction standards. Many CSG companies have other petroleum tenures, and the code will facilitate the ability for petroleum tenure holders to efficiently construct water bores and convert wells to water bores if required.